Generating seismic pulses by compressive force to map fractures

ABSTRACT

The methods described are for determining distribution, orientation and dimensions of networks of hydraulically-induced fractures within a subterranean formation containing fluids. Detectable signals are generated by particles introduced into the fractures. In an exemplary method proppant-like particles are positioned in the formation during fracturing and allowed to generate a signal during or after fracturing activity. The detectable signals generated by the proppant-like particles are used to map fracture space.

CROSS-REFERENCE TO RELATED APPLICATION

The present application is a U.S. National Stage Application ofInternational Application No. PCT/US2013/055608 filed Aug. 19, 2013,which is incorporated herein by reference in its entirety for allpurposes.

FIELD OF INVENTION

The invention relates, in general, to accurately determining thedistribution, dimension and geometry of hydraulically-induced fracturesand fracture networks, i.e., “mapping,” in a subterranean reservoir.More particularly, the invention relates to methods and apparatus forcreating detectable acoustic signals at a plurality of locations withinthe fractures and fracture networks with acoustic particles that arecapable of emitting detectable acoustic signals.

BACKGROUND OF INVENTION

Hydraulic fracturing is used to improve well productivity byhydraulically injecting fluid under pressure into a selected zone of areservoir. The pressure causes the formation and/or enlargement offractures in this zone. Proppant is typically positioned in thefractures with the injected fluids before pumping is halted to preventtotal closure. The proppant thus holds the fractures open, creating apermeable and porous path, open to fluid flow from the reservoirformation to the wellbore. Recoverable fluids, such as, oil, gas orwater are then pumped or flowed to the surface.

The information on the geometry of the generated hydraulic fracturenetworks in a given reservoir formation is critical in determining thedesign parameters of future fracture treatments (such as types andamounts of proppant or fluids to use), further well treatments to beemployed, for the design of the future wells to be drilled, for managingproduction, etc. Therefore, there is a need for accurate mapping of thefractures. The methods typically used include pressure and temperatureanalysis, seismic sensor (e.g., tilt-meter) observational analysis, andmicro-seismic monitoring of fracture formation during fracturingprocesses. Each of these methods have their drawbacks, includingcomplicated de-convolution of acquired data, reliance on assumedparameters, educated “guesswork” as to the connectivity of variousmapped seismic events, and problems associated with reliance onmapping-while-fracturing methods, namely, measuring the shape of thefractures during formation (rather than after closure or duringproduction), measuring fractures which may not be conductive to thewellbore, acoustic “noise” from the fracturing procedures, and aninability to distinguish between seismic events that are caused byfracture formation or other processes.

Methods have been suggested for mapping fractures using explosive,implosive or rapidly combustible particulate material added to thefracturing fluid and pumped into the fracture during the stimulationtreatment, namely, in U.S. Pat. No. 7,134,492 to Willberg, et al.Similar methods are disclosed in Autonomous Microexplosives SubsurfaceTracing System Final Report, Sandia Report (SAND2004-1415), Warpinski,N. R., Engler, B. P., et al., (2004), incorporated herein by referencefor all purposes. However, the suggested practices have significantdrawbacks, including the transport and handling of explosive particlesat the surface and during pumping, exposure of explosive particles tovery high pressures, treatment and wellbore fluids and chemistry,difficulty in controlling the timing of the explosions given theirlengthy exposure to fracturing fluids, exposure of particles tosignificant and high pressures during fracturing, the risk of explosiveparticles becoming stuck in the well completion string, pumping andmixing equipment, etc. Further, some of the proposals require theinclusion of power sources, electronics, etc., in the injected particleswhich may be impractical at the sizes required to infiltrate a fractureand proppant and are relatively expensive.

It is therefore an object of the present invention to provide a newapproach to evaluating hydraulic fracture geometry.

BRIEF DESCRIPTION OF THE DRAWINGS

For a more complete understanding of the features and advantages of thepresent invention, reference is now made to the detailed description ofthe invention along with the accompanying figures in which correspondingnumerals in the different figures refer to corresponding parts and inwhich:

FIG. 1 is a schematic illustration of treatment and monitoring wellswith arrayed sensors for detection and recording micro-seismic eventscaused during hydraulic fracturing;

FIG. 2 is a schematic representation of a simple fracture model such ascreated and populated according to prior art processes;

FIG. 3 is an exemplary embodiment of Attachment Site particles ofdifferent species of particles in a propped fracture space according toone aspect of the invention;

FIGS. 4A-F are graphical representations of exemplary embodiments ofAttachment Site architectures according to aspects of the invention;

FIG. 5 is a schematic representation of an exemplary embodiment of aType-1 particle according to an aspect of the invention;

FIG. 6 is a schematic representation of an exemplary embodiment of aType-2 particle according to an aspect of the invention;

FIG. 7 is a schematic representation of injection of Type-1 particlesinto a simple fracture according to an aspect of the invention;

FIG. 8A is a schematic representation of injection of Type-2 particlesinto a simple fracture according to an aspect of the invention;

FIG. 8B is a schematic representation of a method of attachingAttachment Site, Type-1 and Type-2 particles in a simple fracture andproducing micro-seismic events according to an aspect of the invention

FIG. 9 is a schematic of an exemplary injection tool for injectingparticles into the formation according to an aspect of the invention;

FIG. 10 exemplary flow diagram indicating various steps of preferredmethods according to aspects of the invention is a schematic of anexemplary particle release tool and method according to an aspect of theinvention;

FIGS. 11A-B are schematic views of exemplary Type-3 particles accordingto an aspect of the invention;

FIG. 12 is an schematic view of an exemplary particle Type-3A accordingto an aspect of the invention;

FIG. 13 is a schematic illustration of treatment and monitoring wellswith arrayed sensors for detection and recording micro-seismic eventscaused during hydraulic fracturing according to a method of theinvention;

FIG. 14 is a graphical representation of a simple fracture model;

FIG. 15 is a graphical representation of propped fracture model havingtreated proppant particles, preferably injected by pumping fracturingfluid into the formation, along with treated, reactive proppantparticles according to an aspect of the invention;

FIG. 16 shows an exemplary treated proppant particle, having a coatingover a proppant particle, and exemplary reactive particles according toan aspect of the invention;

FIG. 17 is a graphical representation of a simple fracture model havingcoated reactive particles positioned within the fracture according to anaspect of the invention;

FIG. 18 shows an exemplary coated reactive particle, having a coatingover a reactive core according to an aspect of the invention;

FIG. 19 is a graphical representation of a simple fracture model havingan exemplary acoustic particle according to an aspect of the invention.

FIG. 20 shows an exemplary acoustic particle having a protective layeraccording to an aspect of the invention.

FIG. 21 shows an exemplary acoustic particle having a protective layerand a reactive layer according to another aspect of the invention.

It should be understood by those skilled in the art that the use ofdirectional terms such as above, below, upper, lower, upward, downwardand the like are used in relation to the illustrative embodiments asthey are depicted in the figures. Where this is not the case and a termis being used to indicate a required orientation, the specification willmake such clear. Upstream, uphole, downstream and downhole are used toindicate location or direction in relation to the surface, whereupstream indicates relative position or movement towards the surfacealong the wellbore and downstream indicates relative position ormovement further away from the surface along the wellbore, unlessotherwise indicated.

Even though the methods herein are discussed in relation to a verticalwell, it should be understood by those skilled in the art that thesystem disclosed herein is equally well-suited for use in wells havingother configurations including deviated wells, inclined wells,horizontal wells, multilateral wells and the like. Accordingly, use ofdirectional terms such as “above”, “below”, “upper”, “lower” and thelike are used for convenience. Also, even though the discussion refersto a surface well operation, it should be understood by those skilled inthe art that the apparatus and methods can also be employed in anoffshore operation.

DETAILED DESCRIPTION

While the making and using of various embodiments of the presentinvention are discussed in detail below, a practitioner of the art willappreciate that the present invention provides applicable inventiveconcepts which can be embodied in a variety of specific contexts. Thespecific embodiments discussed herein are illustrative of specific waysto make and use the invention and do not limit the scope of the presentinvention.

Further disclosure regarding micro-seismic event creation during orafter fracturing of a formation, as well as detection of these events,mapping, and other processes discussed herein can be found inInternational Application No. PCT/US2012/32822, to Ersoz, filed Apr. 10,2012, which is incorporated herein in its entirety for all purposes.

FIG. 1 is a schematic illustration of a primary well and monitoringwells with sensors arrays for acquisition and recording of wavesoriginating from the fracture space and traveling through the reservoirformations. In a typical drilling operation, several wellbores are usedin a field to maximize production of hydrocarbons. Production ofhydrocarbons can be enhanced by improving flow of fluids to theproducing well using hydraulic fracturing techniques. The induced andpre-existing fractures create conductive pathways into the producingwells for fluids to flow to the well bore. Fractures formed by hydraulicfracturing methods may extend from the wellbore into the reservoir rockfor as much as several hundred feet. As explained above, typicallyproppant materials are pumped into the fractures during formation to“prop” or maintain the fractures in an open, conductive state. Uponcessation of pumping, the opened or hydraulic fractures collapse orclose for all practical purposes, leaving “propped fractures” open whichare of smaller dimension. “Effective fractures,” meaning the fracturesproviding production fluid conductivity to the wellbore, are typicallyof even smaller dimension.

An exemplary hydraulic fracture (10) is formed by pumping a fracturingfluid (F) into the treatment well (12) at a rate sufficient to increasedownhole pressure to exceed the fracture gradient of the reservoirformation (14). The increased pressure causes the formation rock (14) tofracture, which allows the fracturing fluid (F) to enter and extend thefracture further into the formation (14). The fracturing of formationrock (14) and other events often related to expansion or relaxation offormation rock that change the in situ stress profile and pore pressuredistribution create a plurality of micro-seismic events (16).

As used herein, the term “micro-seismic event” (and similar) refers toany event that causes a small but detectable change in stress andpressure distributions in a reservoir formation, including those causedby slippages, deformation, and breaking of rock along natural fractures,bedding or faults, creation of fractures or re-opening of fractures, andevents artificially created by fracturing operations or caused by anexplosion, implosion, exothermic reaction, etc.

Each micro-seismic event (16) generates seismic, or acoustic, waves(18). The waves generated may be of various types such as body waves,surface waves and others. For the purposes of this invention, the bodywaves are the main point of interest. There are two types of body waves:compression, pressure or primary waves (called P-waves), and shear orsecondary waves (called S-waves). The P-waves and S-waves travel throughthe earth formations at speeds governed by the bulk density and bulkmodulus (rock mechanical properties) of the formation. The rockmechanical properties of the formation vary according to mineralogy,porosity, fluid content, in situ stress profile and temperature.

The terms “seismic wave,” “seismic pulse,” “acoustic wave,” “acousticpulse” and similar, as used herein, refer to detectable and measurableP- and S-waves caused by the micro-seismic event. Each type of wave maybe detected and measured by corresponding sensor equipment, generallyreferred to herein as “seismic sensors” or “acoustic sensors” orsimilar.

The waves (18) propagate away from each micro-seismic event (16) in alldirections and travel through the reservoir formations. These waves aredetected by a plurality of seismic sensors, such as seen at (20) and(21). These sensors (or receivers), which are capable of detecting andmeasuring micro-seismic events, can be of any type, such asseismographs, tilt meters, piezoelectric sensors, accelerometers,transducers, ground motion sensors, multi-axis sensors, geophones and/orhydrophones. Seismic sensors and sensor arrays are commerciallyavailable and known in the industry. The seismic sensors are sensitiveinstruments capable of detecting micro-seismic events (16). The seismicsensors can be placed in a wellbore of one or more observation ormonitoring wells (22). Sensors can also be placed at or near the surface(24), preferably in shallow boreholes (26) drilled for that purpose. Atypical shallow borehole (26) for such a purpose is ten to forty feetdeep.

Micro-seismic monitoring is based on technologies with its originsrooted in earthquake seismology (that is, large amplitude events). Morerecently, with the development of extremely sensitive borehole sensorarray systems and surface monitoring equipment, it has become possibleto detect even very small amplitude events (micro-seismic events) thatcause relatively small changes in stress and pressure distributions fromconsiderable distances. In addition to the sensor technology, dataacquisition, telemetry and processing systems have been developed tohandle these small amplitude events. Consequently, micro-seismic events,which occur at much higher frequencies than surface seismic surveys, canbe measured, even in the presence of “noise” caused by other surface anddownhole activities.

The recorded P- and S-wave data is analyzed, in a process referred to as“mapping” “imaging,” which calculates locations of the events in3-dimensional reservoir space. Typically, a location informationsolution based on a statistical best-fit method is used to map an eventin terms of distance, elevation and azimuth. Analysis of the recordedand measured seismic events will not be discussed herein in detail, asit is known in the art. Software for analyzing and displaying themeasurements and results are commercially available. For example, suchproducts and services are available from Halliburton Energy Services,Inc., under the brand names such as FracTrac® and TerraVista®visualization and interpretation. Further information, including onseismic event detection and analysis can be found in the followingdocuments which are each incorporated herein by reference for allpurposes: U.S. Pat. No. 7,908,230 to Bailey, U.S. Pat. No. 7,967,069 toBeasley, U.S. Pat. No. 7,874,362 to Coates, U.S. Pat. No. 7,830,745 toSuarez; and Patent Application Publication Nos. WO 2008/118986 toCoates, and 2007/105167 to Lafferty.

The accuracy of mapping recorded events is dependent on the number ofsensors spaced across the reservoir and by the distance of the sensorsfrom the measured events. It is beneficial, therefore, to place sensorsin the treatment well. The current micro-seismic monitoring methodssuffer from the fact that the entire process takes place duringhydraulic fracturing. Therefore the recorded data include the “noise” ofthe fracturing process and the results (mapped event locations) are ofopened fractures (rather than propped or effective fractures).

Currently, there is no way to accurately differentiate which eventscorrespond to opened fractures, propped fractures and effectivefractures. The methods described herein make it possible to map theeffective (propped and connected) fracture space by separating themapping survey from fracture formation process. Further, the methodsdescribed herein improve the quality and accuracy of the mapping processby allowing sensors to be placed in the treatment well and withoutinterference from hydraulic fracturing “noise.” Other improvements willbe discussed in the following sections.

Sensors (20) and (21) detect and acquire P- and S-wave data that aregenerated by micro-seismic events (16) and traveled through theformations. The data is typically transferred to data processing systems(25) for preliminary well site analysis. In-depth analysis is typicallyperformed after the raw data is collected and quality-checked. Afterfinal analysis, the results (maps of the fracture networks) areinvaluable in development planning for the reservoir and field, and indesigning future hydraulic fracturing jobs.

FIG. 2 is a graphical representation of a simple fracture model. Asimple bi-wing fracture plane (40) (only one wing shown) extends into areservoir formation (14). A wellbore (60) (cased or uncased) isrepresentative of the wellbore through which the fracturing fluid (F) isintroduced into the zone, i.e. the “treatment well.” The fracturingprocess results in formation of fractures which are initially propagatedalong planes, the orientation of which are dictated by the in situstress profile of the formation (14). Typically, the planes radiate fromthe wellbore (60). Proppant particles (44) are pumped into the fracturesalong with the fracturing fluid. After pumping of the fluid (F) ceases,the fracture closes or seals to an effective fracture (50), indicatedgraphically in cross-sections (52). A typical fracture has a muchgreater length (55) than width (53) and can vary in height (54). Thesedimensions may become critical parameters for selecting size and amountsof proppant, particles and fluid injected into the formation, design ofa fracturing plan, etc.

FIG. 3 is a graphical representation of propped fracture model andAttachment Site (AS) particles (100) that are preferably injected bypumping into the formation along with the proppant particles (44). Asused herein, “injection” and related terms are used to includeinjection, pumping in fluids, and other methods of introducing fluids,slurries, gels, and solid-bearing fluids into a zone of a formationusing methods known in the art. The term is used generically andincludes, as will be indicated in the text, introduction of such fluids,etc., into the zone of the formation from a downhole tool positionedadjacent the zone (rather than pumped from the surface down thewellbore).

The methods presented herein use similar terminology to refer to similartypes of particles, etc. The system will be described using the terms:Attachment Site (AS) particles (or Attachment Sites), Type-1 particles(T1), Type-2 particles (T2) and Type-3 particles (T3). Further, for eachparticle “type,” a plurality of “species” can be employed, designated,for example, as AS-x, AS-y, AS-z, each suffix representing a differentspecies of particle. The species of any one particle correspond tocommon species of the other particles. For example, AS-x particles willinteract with T1-x and T2-x particles and not with T1-y and T2-yparticles. Details are provided below.

FIGS. 4A-F are graphical representations of a number of embodiments ofexemplary Attachment Site architectures. Attachment Site (100) particlesare specially designed to act as “docking stations” for Type-1, -2 and-3 particles. Attachment Site particles do not contain explosives orreactive chemicals.

The AS particles have a functionalized surface layer or coating (102)which is selected and designed to allow attachment of pre-selectedType-1 and Type-2 particles. The process of attracting or attaching ofthe particles (AS, T1, T2, etc.) is primarily based on chemical andphysical properties of the functionalized surface layer.

The Attachment Site particles (100) are preferably pumped with thetreatment fluid (F) and proppant particles (44) into the fracturenetwork (40) and entrapped within the effective fractures (50) when theformation rock closes under overburden pressure once pumping ceases.Alternately, the Attachment Sites (100) can be pumped into the fracturesbefore or after fracture formation, depending on the formation andenvironmental conditions. The Attachment Sites (100) can be injectedinto the formation (14) from the surface or from the wellbore withoutrisk of accidental or premature explosion or reaction since theparticles don not contain any explosive or reactive materials. The AS(100) particles can be mixed with the proppant (44) prior to beingintroduced to the treatment fluid (F) or can be added to the treatmentfluid before, after or along with the proppant throughout the fracturingprocess.

The AS (100) particles are preferably approximately the same size as theproppant particles (44) if they are pumped with the proppant. Asmentioned above, the AS particles are specially designed such that eachAS particle creates a “docking station” that attracts and attaches toonly selected Type-1 and Type-2 particles. The AS particle can be astructural particle, such as a sphere, spherical shell, lattice,latticed particle, segmented particle, or other structural particleproviding particle-specific attachment sites. Such a “structuralparticle” has no part in the process of creating a micro-seismic event.That is, the structural AS particle does not itself react or explode.The attachment mechanism can be based on one or more properties of thefunctionalized layer. Attachment can be based on one or more mechanical,electrical, magnetic, or chemical processes, or a combination of any ofthese processes. Structural properties, such as shape, materialcomposition, electrical charge, super-paramagnetic behavior,“tentacles,” “sockets,” etc., can be used.

Additionally, more than one “species” of Attachment Site particle (100)can be deployed into fracture space such as AS-x (100-x), AS-y (100-y)and AS-z (100-z) as shown in FIG. 3. For example, a plurality of ASparticles of species-x (AS-x) (100-x) can be pumped into the formationfractures along with a plurality of other species of AS particles, suchas AS-y (100-y), AS-z (100-z), etc. When multiple species of ASparticles are present in the fracture space, it is possible to conductsequential (time-lapse) micro-seismic surveys by deploying and/oractivating a first species of energetic particles (e.g., T1-x and T2-x),and at a later time deploying and/or activating another species ofenergetic particles (e.g., T1-y and T2-y). All of the particles aredesigned to allow attachment only to the same selected particle species(e.g., T1-x to AS-x, T1-y to AS-y, but not T1-x to AS-y, etc.). In sucha manner, multiple micro-seismic surveys are possible at different timesdeploying only one species of the energetic particles for the firstsurvey and another species of energetic particles for the second surveyat a later time.

The Attachment Sites shown in FIGS. 4A through 4F are exemplaryembodiments of AS particles according to aspects of the invention. Anumber of AS particle forms (100, 110, 120, 125, 130, 140) are shown.

An exemplary form of AS particle, seen in FIG. 4A, is a multi-componentstructure having a solid or hollow “core” section (105), an inner layer(106) and an outer layer (104), a functionalized surface “coating”(102), and a plurality of attachment features (103), such as “sockets”or “ports,” or “tentacles” or other extending structures (101).Additional attachment features or attachment properties may be used. TheAS particle core section (105) can be solid or hollow and may servemerely for supporting an attachment layer, supplying structuralintegrity, or storing of functional materials that contribute to“attraction” or “attachment” functionality. For example, the core caninclude super-paramagnetic particles, magnetic ionic liquids,ferro-fluids, super-capacitors, etc. For protecting the properties ofthe AS particles while being injected, a protective layer (107) may beincorporated. This protective layer may be designed to decompose,dissolve, decay or otherwise dissipate over time, upon contact with aselected fluid (in situ or introduced), such as a solvent, acid, brine,water, etc., or upon exposure to other environmental parameters, such astemperature, pressure, salinity, pH, etc.

The various surface features described can be created usingmicro-encapsulation processes and other chemical techniques, as areknown in the art, including pan coating, air-suspension coating,centrifugal extrusion, vibration nozzle, spray-drying, ionotropicgelation, coacervation, interfacial polycondensation, interfacialcross-linking, in situ polymerization, matrix polymerization, waterbeds, etc. One or more shell, membrane or coating layers can be used andthe core particles can be hollow, solid, liquid, gel, etc. The shellsand layers need not completely surround the core.

Other embodiments of AS particles are seen in FIGS. 4B-F. In FIG. 4B, anAS particle (140) is seen with a functionalized surface layer (142),such as cross-linked fibers, attachment features (143) such as sockets,an outer layer (144) for support and an inner layer (146). In FIG. 4C,an exemplary AS particle (130) has a functionalized surface (132), suchas oriented long fibers, attachment features (133), like sockets, anouter layer (134) and an inner layer (136). In FIG. 4D, a hollow ASparticle (120) is presented, having a plurality of surface features(123), namely, ports, defined by an outer layer (124) of supportinglatticework. Functionalized surface areas (122) can be defined acrossthe latticework. In FIG. 4E, an AS particle (110) is shown havingattachment features, such as tentacles (111) and sockets (113), afunctionalized surface (112), and an outer layer (114). In FIG. 4F, anexemplary AS particle (125) is seen with a functionalized surface (128)having attachment features, such as tentacles (127) and ports (128)formed by linked molecules or other structures over an outer layer(129).

The AS particles are not reactive to create seismic events, thusproviding safe transport, handling, mixing, etc., prior to and duringdeployment. Preferably, the AS particles do not attach to proppantparticles, especially if injected into the fracture space afterhydraulic treatment. Some layers (104, 134) are shown on FIG. 4 ascompletely surrounding the underlying layers (106, 136) or core (105).Other arrangements can be employed, as shown (122, 128), where innerlayers are not surrounded by outer layers. Although Attachment Sitesshown in FIG. 4B are generally spherical, they may take other shapes,such as ellipsoids, cylinders, or any other 3-dimensional shapes.

FIG. 5 shows an exemplary embodiment of a Type-1 particle. Type-1 (T1)particles (150) consist of a core section (154) carrying a “payload” ofspecially designed or selected energetic materials used to create amicro-seismic event. The functionalized surface layer (153), withoptional attachment features such as “tentacles” (156) and “sockets”(155), facilitates the attraction and attachment process by providingproperties corresponding to those of the AS particles, as describedabove.

An exemplary shell layer (152), which can be rigid or flexible, providesthe support for the outer attachment layer (153) and encapsulates theenergetic material of the core (154). In this case, a protective ordecay layer is not necessary, as the shell layer (152) providessufficient stability to reach the attachment site intact. However, suchlayers may be used. The shell layer (152) can have multiple layers (152a) and (152 b).

The T1 particle “payload” of energetic material is contained in the core(154) and is selected to react with a corresponding “payload” ofenergetic material in a Type-2 particle. Contact or proximity ofcorresponding Type-1 and Type-2 energetic materials interact to producea micro-seismic event, such as a detonation, explosion, implosion,exothermic reaction, violent chemical reaction, etc. This process isexplained further below. Each Type-1 particle core section carries a“payload” of reactive material for use in creating the micro-seismicevent. The concept of payload is familiar to those of skill in the artand can be used to determine the number of Type-1 particles to beinjected into the formation, the ratio of Type-1 to Type-2 and ASparticles, etc.

When the Type-1 particles are introduced into a fracture network with ASparticles present, the shell or attachment layer (153) will attach,mechanically, chemically, etc., to the Attachment Site particlesscattered throughout the fracture network. Additional layers or shellscan be employed to provide or improve other properties, such assurvivability, mobility, flexibility, etc.

The Type-1 particles are preferably of a much smaller size than theproppant or Attachment Site particles. Since the Type-1 particles arepreferably introduced into the formation after completion of fracturing,the particles must be able to disperse and move freely in the spacesbetween the proppant and Attachment Site particles already in place.

As with the Attachment Site particles, multiple species of Type-1particles can be introduced into the formation fractures. Each speciesof Type-1 particle, such as Type-1 particle of species-x (150-x),species-y (150-y) and/or species-z (150-z), are selected to attach onlyto AS particles of the same species. Hence, multiple species of Type-1particles can be introduced into a fracture and selectively attached tocorresponding species of AS particles for the purpose of performingsimilar surveys at different times.

FIG. 6 shows an exemplary Type-2 particle according to an aspect of theinvention. Type-2 (T2) particles (160) are similar to Type-1 (T1)particles and preferably consist of a core section (164) carryingspecially designed or selected materials which will be used to create amicro-seismic event. That is, the payload of the core section (164) ofthe Type-2 particles (160) will interact with additional particles,components, or payloads to produce a micro-seismic event such as adetonation, explosion, implosion, chemical reaction, etc. Type-2particles also preferably have one or more layers or shell sections(162). Preferably the shell sections (162) form a layer or encapsulatethe core section (164), thus preventing the core section from reacting,etc., before planned. The shell sections (162) are specifically designedor selected to attach to a corresponding Attachment Site particle (100).When the Type-2 particles (160) are introduced into the fracture space,the functionalized surface layer (163) section causes attraction orattachment to Attachment Site particles scattered throughout thefracture network. Attachment features (165), such as sockets, can beemployed as well. The various layers, such as shell (162), canthemselves have multiple layers.

The protective and decay layers may not be necessary where the layer ofthe core section provide the structural stability necessary to reach anattachment site, the reactivity to react with corresponding particlesupon a triggering event, and the structure, chemistry or characteristicto attach as required.

The Type-2 (160) particles are preferably much smaller than the proppantparticles and Attachment Site particles. Since the Type-2 particles arepreferably introduced into the formation after completion of fracturing,the particles must be able to disperse and move freely in the spacesdefined between the proppant and Attachment Site particles. The Type-1and Type-2 particles can be of similar or dissimilar size. In apreferred embodiment, the Type-2 particles are smaller than the Type-1particles, which are, in turn, smaller than the AS particles. While thevarious particles (proppant, Attachment Site, and Type-1 and Type-2),are shown as spherical for ease of illustration, it is understood thatother shapes can be employed with or without the surface featuresmentioned elsewhere herein, and that the selection of shape may be usedto allow, disallow, enhance or reduce attachment of selected particlesto one another. Additional layers or shells can be employed, such asdecay layers as described elsewhere herein.

As with the Attachment Site and Type-1 particles, multiple species ofType-2 particles can be introduced into the formation fractures. Eachspecies of Type-2 particle, such as Type-2 particles (160-x), (160-y)and (160-z), are selected to attach only to AS particles and/or Type-1particles of the same species. Hence, multiple species of Type-2particles can be introduced into a fracture and selectively attach tocorresponding species of AS or Type-1 particles.

FIG. 7 is a schematic representation of a plurality of Type-1 particlesbeing introduced into a propped fracture space. As in FIG. 2, presentedis a graphic representation of a simple fracture model having a simplebi-wing propped fracture (50) (one wing shown) extending into aformation zone (14). The wellbore (60) is representative of a wellborefrom which fracturing fluid (F) is introduced into the formation.Proppant particles (44) are pumped into the fractures. After pumping ofthe fracturing fluid (F) ceases, the exemplary fracture (40) closes orseals to form an effective fracture (50). The AS particles (100) arepumped or introduced into the formation either along with the proppantor separately. The Type-1 particles (150) are shown being introducedinto the formation using a particle release or injection apparatus(180), here bracketed by upper and lower packers or other sealingmechanisms (182, 184), sealing a section of the wellbore for injectingthe formation. Alternately, Type-1 particles can be introducedconcurrent with the proppant particles and/or AS particles. Multiplespecies of Type-1 particles, such as T1-x (150-x), T1-y (150-y), etc.,can be injected for the purpose of performing similar surveys atdifferent times.

The insets show a plurality of Type-1 particles of species-x (150-x)attached to an AS particle of the same species (100-x) and a pluralityof Type-1 particles of species-y (150-y) attached to an AS particle ofthe same species (100-y) for the purpose of performing similar surveysat different times.

FIG. 8A is a schematic representation of a plurality of Type-2 particles(160) being introduced into a propped fracture space (50). A simplebi-wing fracture (50) extends into a formation zone (14). As explainedabove and shown on FIG. 8A, Type-2 particles may be injected into thefracture space following the injection of Type-1 particles. Here Type-2particles (160) are shown being introduced into the formation using aparticle release or injection mechanism (180), bracketed by upper andlower packers or other sealing mechanisms (182, 184), sealing a sectionof the wellbore. The delivery tool (180) injects Type-2 (160) particlesinto the formation, such as through nozzle (186). Alternately, Type-2particles can be introduced concurrent with the proppant particlesand/or AS particles. The insets show multiple Type-2 particles ofspecies (160-x, 160-y) attached to AS particles of matching species(100-x, 100-y) and/or to Type-1 particles of similar species (150-x,150-y). One or more Type-2 (160) particles can attach to a single AS(100) particle. As explained elsewhere, the AS particles may be merelystructural or can be comprised of one or more chemical. As alsoexplained elsewhere, the Type-1 and Type-2 particles can have core andshell sections, as desired, to facilitate attachment and to isolate coresections. The insets are enlarged detail schematics of exemplary ASparticles (100-x, 100-y) with attached Type-1 particles (150-x, 150-y)and Type-2 particles (160-x, 160-y).

FIG. 8B is a schematic representation of a preferred method according toan aspect of the invention where the sequence of events following theattachment of Type-2 particles to Type-1 and/or Attachment Sites areshown as depicted by letters A through F. The first species of ASparticles (100-x) with attached corresponding first species Type-1 andType-2 particles (150-x) and (160-x) are in place in the proppedfracture space (50). A chemical or explosive reaction starts when Type-1and Type-2 particles (150-x) and (160-x) are attached to an AS particleand/or proximate or in contact with each other. The shells containingthe core payloads of Type-1 and Type-2 particles begin to coalesce.Protective shells, when present, are dissipated, by heat, time,pressure, chemical, etc., as explained above, so the payload materialscan interact. When the payloads of Type-1 and Type-2 particles (150-x)and (160-x) come into contact, or effective proximity, an energeticreaction initiates, thereby creating a micro-seismic event. Such eventsoccur at all Attachment Sites having sufficient Type-1 and Type-2particles attached. A single reaction can trigger reactions in localparticle clusters.

The reaction (170) caused by the mixing of Type-1 and Type-2 particlepayloads may be a chemical exothermic reaction, a low or high orderdetonation, deflagration, or combustion in a confined environment underelevated pressure and temperature as dictated by the reservoir formationenvironment and the materials used in the Type-1 and Type-2 payloads.Following the reaction (170), a micro-seismic event (16) occurs which asdescribed elsewhere herein causes waves (18) to radiate from the eventsite and travel through the subterranean formations. The waves aredetected by sensors, such as sensor (21), for example, positioned in thewellbore. Other sensors positioned in monitoring wells (22), the surface(24), or in shallow surface wells (26), also receive the waves, whichare detected and recorded as wave data (172) at recording stations (25).Micro-seismic events (16) occur at a plurality of AS particle locationsspread across the effective fracture space (50), providing enoughmicro-seismic events to provide accurate and detailed mapping orsurveying of the effective fracture space.

Also seen in FIG. 8B are additional species (-y, -z) of AS particles(100-y, 100-z). One or more of the species of Type-1 and/or Type-2particles can be introduced to the fracture space concurrently or atspaced apart times. The use of particle species allows for multiplemapping surveys to be performed. Where an initial survey is run usingspecies-x, the AS-y and AS-z particles remain intact. A later survey,using the remaining species of AS particles, can be performed later,either by injecting Type-1 and/or Type-2 particles of the remainingspecies, or by “triggering” (by heat, pressure, time, chemical, etc.)such particles which were previously pumped into position.

The “time-lapse” mapping concept allows the operator to further managereservoir production and planning by observing changes over extendedperiods of reservoir life. For example, a survey using the first speciesof particles can be performed after a fracturing operation has beencompleted, but before production has started, to map the proppedfractures. A second survey, using another species of particles, may beperformed after a selected period (hours, days, months) of production tomap the effective fracture space at that time. Another survey can beconducted after a longer production period with yet another species ofparticles.

The surveys should preferably be performed when the “noise” generated byunrelated events are minimized to improve signal to noise ratio, therebyimproving quality and accuracy of the mapping.

Current technology is capable of detecting micro-seismic events whichcause pressure changes of as little as tens of psi. Future technologymay push that limit of detectability further to lower pressure amplitudepulses. For reference, a measurable micro-seismic event may beequivalent to an event caused by detonation of approximately 1 milligramof common explosive, such as TNT. For comparison, a typical perforationshaped charge is about 10-40 grams of explosives and may cause pressurewaves of millions of psi. The goal is to select and operate particleagglomerations which create measurable micro-seismic events fromdistances (event to sensor) of 30-1500 feet. But the event should alsobe small enough to meet safety concerns.

The proppant particles are sized by “mesh size” typically. The mesh sizeof the proppant will generally determine the size of AS and Type-1 orType-2 particles which can effectively be used. In a preferredembodiment, the AS particles are approximately the same size as theproppant particles. Similarly-sized AS particles can be easily mixedwith and dispersed in the proppant. Larger or smaller AS particle sizesmay also be used. Particles which are injected or released to thefracture space after the fractures have closed, such as Type-1 and/orType-2 particles, are preferably considerably smaller than proppant orAS particles so they can effectively flow through the porous spaceformed by the trapped proppant particles in the fracture space. As anexample, a typical Type-1 and/or Type-2 particle may be between 1/14thand 1/318th the size of an AS or proppant particle. Such a size allowsthe particles to flow through the proppant and allows multiple particlesto attach to one or more AS particles. These approximate figures arebased on spherical geometries; therefore other sizes may be desirable toaccommodate non-spherical particle geometry.

The concept of Attachment Sites allows the micro-seismic event density,that is, the number of micro-seismic events generated (and measured) perunit volume of fracture space, to be selected during the design phase ofthe survey. Similarly, the ratios and amounts of the Type-1 and/orType-2 particles can be selected based on payload, attachment mechanism,volume of disbursement, density of AS particles, etc. for eachindividual survey depending on the reservoir properties, environmentalconditions and a number of other variables As an example, for amicro-seismic survey where 1 mm size proppant and the same size ASparticles are used, if the desired survey of micro-seismic events isabout one per square meter of fracture space, then the required ASconcentration would be approximately 1 AS particle per 1 millionproppant particle for every mm of fracture width. Hence, if theestimated eventual fracture width is calculated to be approximately 3mm, then the AS to proppant ratio should be targeted at about 3-5 ASparticles per 1 million proppant particles, allowing for non-uniformdistribution and other losses. In practice this results in a veryworkable amount of AS particles for such a survey. Assuming similar bulkdensities for proppant and AS particles, the above example requires 3-5pounds of AS particles per million pounds of proppant. Preferably a muchhigher number of Type-1 and/or Type-2 particles are injected to insuresufficient numbers reach and attach to the AS particles, providesufficient payload at any given attachment site to ensure a measurablemicro-seismic event, etc.

Triggering events cause initiation of the micro-seismic events. In apreferred embodiment, after the AS, Type-1 and/or Type-2 particles arein position, dispersed at locations throughout the fracture space, thereactive particles are triggered by a triggering event to initiatemicro-seismic events at each location. The triggering event can includemultiple stages, such as a decay stage for removing decay layers fromthe particles. The decay stage can, for example, include methods such asinjecting a fluid (brine, acid, chemical wash, etc.) into the formationto dissolve or otherwise remove any decay layers. Alternately, the decaystage can employ a change in an environmental condition such astemperature, pressure, salinity, pH, etc. For example, high salinitywater can be injected to dissolve one or more decay layers on one ormore particles, thereby triggering a reaction between the now-exposedcore sections of the Type-1 and Type-2 particles. Alternately, thetriggering event can simply be a time delay during which the protectiveshells dissipate and/or coalesce allowing the reactive payloads to comeinto contact and/or to mix with each other thereby initiating areaction.

The core sections of the Type-1 and Type-2 particles carry payloads ofexplosive or reactive material (or initiating, catalytic materials,etc.) which, upon contact with the other core section material(s), causethe explosion, reaction, etc.

Where multiple species of AS, Type-1 and Type-2 particles are employed,various triggering events may be selected to start successive series ofmicro-seismic events for each species type. It is also possible torelease Type-2 particles which simply react immediately upon contactwith the Type-1 particles. The micro-seismic events would then occur asthe Type-2 particles are injected and progress through the fracturespace and become attached to type-1 particles of the same species.

FIG. 9 is a schematic of an exemplary particle injection and releasetool (180) and method according to one aspect of the invention. An uppersealing assembly (182) and a lower sealing assembly (184), such aspackers, are positioned in the wellbore (60) above and below a zone ofthe fracture space (50) targeted for injection of Type-1 and/or Type-2particles. The upper sealing assembly (182) can surround the releasetool or a portion thereof, such as delivery nozzle (186). The injectionapparatus (180) can be lowered in to the well on the completion tubingstring, coiled tubing, slick line or wire line. The apparatus (180) hasan injection pump (185) and several chambers (188-A, 188-B, etc.) fordifferent types of particles and fluids. The adjustable pressure andoutput rate pump (185) and the nozzle (186) push the contents of aselected chamber into the fracture space. The particles are delivered ina suitable fluid. In a preferred embodiment, where multiple types orspecies of particles are to be injected, the separate particle types orspecies are contained in separate chambers (188-A) and (188-B) of thetool and are injected separately and sequentially. The injection system(internal piping, pump and nozzle) is flushed with a suitable type offluid before and after each injection where the particle type ischanged, as desired. An actuator (185) for injecting the particles isknown in the art, including a submersible pumps, hydraulic or electricactuators, a DPU, etc.

Advancements over prior art included in the inventive methods areinjection or introduction of the reactive particles after conclusion offracturing and/or without mixing of the particles at the surface or inthe wellbore above the formation. Further, the reactive or energeticparticles are not then prone to accumulating in unwanted areas, such asin a mixer, at the surface, along the wellbore, etc.

Other release mechanisms may be employed. For example, the AS particlesmay also be injected or pumped into the formation using a downhole toolafter completion of fracturing processes. However, this wouldnecessitate the use of AS particles of much smaller size, to flowthrough the proppant particles, which would compromise theireffectiveness as attachment sites, especially where designed to attractand attach to multiple reactive particles.

FIG. 10 is an exemplary flow diagram indicating various steps ofpreferred method according to aspects of the invention as explainedabove. The flow diagram applies to a first method. For other methods,not all of the steps must be performed, nor must they be performed inthe order presented. Variations are presented and discussed herein andwill be recognized and understood by those of skill in the art. In FIG.10, the process is shown divided into three stages (400), (500) and(600) indicating “fracturing,” “surveying,” and “data processing”stages, respectively. The fracturing fluid is pumped into the targetzone of the formation, into existing fractures and creating additionalfractures at (420). The fracturing fluid contains or delivers proppantparticles to prop open the fractures. Also at (420), Attachment Sites(AS particles) are injected into the fractures mixed with the proppant.Multiple species of AS particles may be utilized, but for thisdiscussion it is assumed that only two species, AS-x and AS-z are used.At (430), pumping operations are ceased. At this stage, open fracturestypically close, except where the proppant and AS particles have beenplaced in the fracture space. Next there may be a “clean-out” stage(440) during which well is allowed to flow-back, to clean the fracturingfluids from the reservoir formations. At (510), a particle injection orrelease tool is deployed adjacent the zone of interest and one of thetwo species, for example Type-1, species-x, particles are injected intothe zone. The T1-x particles travel in the fracture space and attach toAS-x particles. At (520), Type-2, species-x, particles are injected intothe zone and attach to either the AS-x or T1-x particles, or both. At(530), a first triggering event occurs, allowing or causing contactbetween the reactive materials in the T1-x and T2-x particles at eachattachment site. At step (550), a set of micro-seismic events occur,caused by the reactions of payload materials, causing seismic waves totravel in all directions throughout the formations. At (610) themicro-seismic events (or the waves thereof) are detected by sensors.Various stages of data processing follows, such as recording, transfer,filtering, clean-up, quality-check, etc., at (620). Other steps caninclude preliminary field processing at (630), transfer to dataprocessing centers at (640) and final processing and output for fracturemapping at (650).

All or part of the surveying (500) and data processing (600) stages maybe repeated at a later time using additional species (T1-z and T2-z), toprovide a second fracture mapping survey, allowing a “time-lapse”capability.

Additional methods are presented for producing a plurality ofmicro-seismic events in a fractured formation. The following methodsdescribed are derived from the previously described method and detailswill not be repeated. Details of the primary method are applicable tothe following methods, with exceptions and differences indicated below.

Another preferred method does not employ Attachment Site particles. Inother words, no AS particles are positioned within the effectivefracture space. Type-1 particles are injected or introduced into thepropped fracture space after fracturing has ceased. Multiple species ofType-1 particle may be introduced. The Type-1 particles may have thestructures (core, layers, etc.) and chemistry as discussed elsewhereherein. Preferably the Type-1 particles have a reactive material coresection and an attachment layer for attaching Type-2 particles.

After dispersal of the Type-1 particles within the propped fracturespace, a first species of Type-2 particles are introduced into thefracture space. Type-2 particles preferably have a core sectionspecifically designed or selected to initiate a reaction withcorresponding Type-1 particle cores. One or more layers of the Type-2particles facilitate attachment to the Type-1 particles.

Multiple species of Type-2 particles may be used for multiple surveys asdescribed above. The various species can be introduced to the fracturenetwork simultaneously and triggered by separate triggering events, orcan be introduced sequentially after triggering of previously introducedspecies.

In another embodiment, Attachment Site particles and Type-1 particlesare incorporated. These particles can be described as “modified” Type-1particles that have many of the characteristics of the above-describedAS particles. For example, the modified T1 particles can be larger,stronger, or use attachment features such as latticework, ports, etc. Inthis method, modified Type-1 particles are mixed with proppant andpumped into the fracture space. When pumping ceases, the particles areentrapped within the fracture network. The modified Type-1 particles areexposed to high pressures and fracture fluid chemistry during pumpingand entrapment and it is expected that many of them may not survive.This disadvantage may be compensated for by increasing the concentrationof modified Type-1 particles within the proppant. Multiple species ofmodified Type-1 particle may be introduced. It should be noted that thepayload of the modified Type-1 particle does not present a hazard duringthe pumping stage as it contains only one of the components required forthe energetic reaction. After a suitable period of time has passed toallow for optional clean-up, etc., the first species of Type-2 particlesare introduced into the fracture network. Type-2 particles preferablyhave cores of specifically designed or selected materials that initiatereactions with corresponding Type-1 particles. One or more layers of theType-2 particles facilitate attachment to the Type-1 particles. Multiplespecies of Type-2 particles may be used for multiple surveys asdescribed above. Multiple species may be introduced to the fracturenetwork simultaneously or sequentially and react upon separatetriggering events.

FIG. 11A is a schematic view of an exemplary Type-3 particle for usewith Attachment Sites according to an aspect of the invention. TheType-3 particle (200) incorporates the materials required for anenergetic reaction in its inner core (204) and outer core (210)sections, and separated by a partition (206). The outer shell (216) andfunctionalized surface (220) may incorporate surface features such assockets, ports, or tentacles (221, 222, 223). Type-3 particles may bethought of as an agglomeration of the characteristics of Type-1 andType-2 particles.

According to an exemplary method, Attachment Sites (AS) of severalspecies are pumped with the fracturing fluid into the fracture networkand entrapped. As described herein, the AS particles are suitableproppant size particles that have specially designed outer shells suchthat each AS creates a “docking station” that attracts and accepts onlya specific “species” of Type-3 particles. Type-3 particles are thenintroduced into the fracture space. Type-3 particles (200) have an innercore section (204) which carries a payload of selected materials thatreact with the payload materials contained in outer core (210). Aseparation layer or capsule (206) separates the inner and outer coresections. The partition (206) can be triggered to allow contact betweenthe payloads, such as by means of changes in environmental conditions(e.g., temperature, pressure, etc.) or by time decay, etc., as discussedabove. The partition (206) can be a membrane, coating, layer or multiplesuch mechanisms. An outer shell (220) consists of one or more layers ofselected materials to isolate the outer core materials from theenvironment until an appropriate triggering event. The selectivity ofType-3 particles based on the “species” concept described above canapply as well.

FIG. 11B shows an alternative embodiment of Type-3 particle for use withAttachment Site particles. Similar parts are numbered and not discussed.Additional attachment features (222) are present. Additional layer (216)can provide a protective coating, a time-delay coating, etc.

FIG. 12 is a schematic illustration of an embodiment of a Type-3particle for use without Attachment Sites. The Type-3 particles (250)are preferably injected after fracturing processes have ended. After asuitable period of time has passed to allow for optional clean-up, etc.,a first species of Type-3 particle is introduced. The Type-3A particlemay have two compartments (260) and (280) for the payload materials(204) and (210) separated by one or more partitions (270). Thecompartments (260, 280) carry the payload of materials that initiate areaction as described above. The partition (270) separating thecompartments can be triggered to bring into contact the contents of thecompartments, such as by means of changes in environmental conditions,time decay, etc. The partition can be a membrane, coating, layer ormultiple such mechanisms. When the partition (270) has been removed,deactivated, dissipated, etc., by the triggering event, the payloadscreate a reaction producing a micro-seismic event. An outer shell (290)consists of one or more layers of selected materials to isolate thecompartments (260, 280) from the environment until an appropriatetriggering event. The surface functionality of the modified Type-3particle used for this method does not incorporate attachment features.The modified Type-3 particles are able to freely travel though theproppant particles without accumulating at docking sites.

Attachment sites (docking stations), Type-1, Type-2 and Type-3 particlescan be of any suitable size and shape to fit the fracture space and tocontain required amounts of materials.

The outer layer (shell, capsule or coating) design of the AttachmentSites, Type-1, Type-2 and Type-3 particles determine the unique speciesof the particles in such a way that only the same species of componentsattach to each other. By this concept of distinct and separate speciesof particles, it is possible that the system may be operatedselectively, as and when needed, by later introducing or triggeringdifferent species of particles (assuming this species of the AttachmentSites were entrapped within the fracture space).

The outer layer section of Type-1, Type-2 and Type-3 particles can besufficiently elastic to enable the particles to deform withoutstructural damage to pass through restrictions.

The preferred methods, where only the Attachment Sites are pumped withthe proppant during the fracturing process, have distinct advantages,such as preventing premature exposure of the energetic payloads to harshconditions or chemicals present in treatment fluids.

The methods are capable of selectively activating varying amplitude(strength) seismic events at controlled times by using the deliverydevices and methods explained herein.

The release mechanism design for T1, T2, and T3 particles allowsselective surveys within fracture networks created by multi-stagehydraulic stimulation jobs.

The system allows “Time-lapse” surveys to be performed as and whenrequired.

FIG. 13 is a schematic illustration of treatment and monitoring wellswith arrayed sensors for detection and recording micro-seismic eventscaused during hydraulic fracturing according to a method of theinvention. An effective fracture (50) has been formed in treatment well(12) in formation (14). Micro-seismic events (16) are caused accordingto the methods described herein. The micro-seismic events generateseismic waves (18). The waves (18) propagate away from eachmicro-seismic event (16) in all directions and travel through thereservoir formation. The waves are detected by a plurality of seismicsensors, such as seen at (20) and (21). The seismic sensors can beplaced in a wellbore of one or more observation or monitoring wells(22). Sensors can also be placed at or near the surface (24), preferablyin shallow boreholes (26) drilled for that purpose. Sensors (20) and(21) detect P- and S-wave data (172) from micro-seismic events (16). Thedata is typically transferred to data processing systems (25) forpreliminary well site analysis. In-depth analysis is typically performedafter the raw data is collected and quality-checked. After finalanalysis, the results (maps of the fracture networks) are invaluable indevelopment planning for the reservoir and field, and in designingfuture hydraulic fracturing jobs.

The particle shells, layers or coatings are preferably made of one ormore of the following chemicals in the following Groups, alone or incombination, and may be cross-linked at any percentage by any number ofmeans known in the art, in single or multiple layers over a particlecore section or sections. Exemplary shell, capsule or coating materialsinclude:

-   -   materials containing hydrocarbons in acid or salt form, with or        without monomers or polymers, such as, Alkenes, Polyethylene,        Polypropylene, Polycarbonates, Polycondensates, Benzene        derivatives, Styrene, Polystyrene, Alkene derivatives (Vinyl        Groups and Vinyl Polymers), Polyvinyl nitriles, Polyvinyl        alcohols, Polyvinyl ketones, Polyvinyl ethers, Polyvinyl        thioethers, Polyvinyl halides    -   materials containing oxygen in acid or salt form, with or        without monomers or polymers, such as, Acrylic Acid, Methacrylic        Acid, Itaconic Acid, Oxalic Acid, Maleic Acid, Fumaric Acid,        Phthalic Acid, Carbolic Acid (Phenol), Fatty acids, Malonic        Acid, Succinic Acid, 2-acryloyloxyethylsuccinic acid,        2-acryloyloxyethylphthalic acid, 2-methacryloyloxyethylsuccinic        acid, 2-methacryloyloxyethylphthalic acid, Polycarboxylic acid,        Polyacrylic acid, Polymethacrylic acid, Epoxides, Ethylene        oxide, propylene oxide, Esters, Methyl acrylate, Ethyl acrylate,        Methyl methacrylate, Polymethyl methacrylate, Polyethylene        glycol, Polypropylene glycol, Polytetramethylene glycol,        Polytetramethylene ether glycol, Polyether ketones, Polyesters,        Polyarylates, Polycarbonates, Polyalkyds, Aldehydes,        Formaldehyde, Acetaldehyde, phenol formaldehyde resins,        Carbohydrates, Polysaccharide containing amine groups,        Peroxides, Sodium peroxydisulfate, and Potassium        peroxydiphosphate    -   materials containing Sulphur in acid or salt form, with or        without monomers or polymers, such as, Sulfonic Acids,        2-Acrylamido-2-methyl-1-propanesulfonic Acid (AMPS), Poly        2-acrylamido-2-methyl-1-propanesulfonic acid (PAMPS),        4-Styrenesulfonic acid, Vinyl sulfonic acid, styrene sulfonic        acid, butylacrylamide sulfonic acid, alkyl or aryl sulfonic        acids, methacryl sulfonic acid, 2,3,4-Acryloyloxyethane sulfonic        acid, 2,3,4-Methacryloyloxyethane sulfonic acid, Polystyrene        sulfonic acid, Polyvinyl sulfonic acid, Sulfones, Dimethyl        sulfate, Sodium polystyrene sulfonate, Sodium styrene sulfonate,        Alkyl sulfonates, Polysulfones, Polyarylsulfones,        Polyethersulfones, Polysulfonates, Polysulfonamides, Sulfides,        Polysulfides, Polyphenylene sulfide, sulfoethyl acrylate,        sulfoethyl methacrylate, sulfopropyl acrylate, sulfopropyl        methacrylate, sulfoaryl acrylate, and sulfoaryl methacrylate    -   materials containing Phosphorus and Fluorine in acid or salt        form, with or without monomers or polymers, such as, Phosphate,        Trimethyl phosphate, Phosphoric acid, Polyphosphazenes,        Fluorinated ethylene propylene, Polytetrafluoroethylene,        perfluoroalkoxy polymer resin, Ammonium salts, Alkaline or        Alkali Metal Salts of Sulfate or Phosphate)    -   materials containing Nitrogen in acid or salt form, with or        without monomers or polymers, such as, Amines, Primary,        secondary, tertiary fatty amines, Hexanediamine, Polyamines,        Ethylenediamine, Diethylenetriamine, Triethylenetetramine,        Polyalkylamines, Amides, Dimethylformamide, Acrylamide,        Polyamides, Polyphtalamide, Imines, Aziridine, Polyethylene        imine, Imides, Polyimides, Polyetherimides, Polyamide-imides,        Alkyl amines, Ethanolamine, methylamine, Cyclic amines,        Aziridine, Ployethylene amine, Aromatic amines, Aniline,        Polyaniline, Cyanates, Isocyanates, Methyl cyanate, Methyl        isocyanate, Resins, Polyaramides, Polyamidemides, Hydrazine        derivatives, monomethyl-hydrazine, dimethyl-hydrazine    -   materials containing Thermoplastics and other Polymers, such as,        Polymaleicanhydride octadecene, Polybenzoxazoles,        Polybenzimidazoles, Polyureas, Polyurathanes, Polysilazanes, and        Polysiloxanes

The particle core sections of energetic or reactive materials, are madeof one or more of the following chemicals, alone or in combination, andmay be combined at any percentage by any number of means known in theart, in any total weight to achieve a sufficient specific energy togenerate the required micro-seismic event strength. Exemplary core andpayload materials include:

-   -   high-order explosives such as Pentaerythritoltetranitrate        (PETN), Hexamethylenetetraminemononitrate,        Cyclotrimethylenetrinitramine (RDX),        Cyclotetramethylenetrinitramine (HMX),        Hexanitrohexaazaisowurtzitane (HNIW), Hexanitrosilbene (HNS),        Picrylamino-3,5-dinitropyridine (PYX), Diazodinitrophenol        (DDNP), Lead Azide, Silver Azide, Hydrazine Azide,        Trinitrotoluoene (TNT), Polyazapolycyclic caged Polynitramines        (CL-20), 2,4,6-Trinitrophenylmethylnitramine (Tetryl)    -   energetic plasticizers such as Nitroglycerine (NG),        Ethyleneglycoldinitrate (EGDN), Acetone Peroxide, bis(2,2        di-nitropropyl) acetal/formal (BDNPA/BDNPF), Triethylene        glycol-dinitrate (TEGDN), Diethylene glycol-dinitrate (DEGDN),        Trimethylolethane Trinitrate (TMETN),        1,2,4-Butanetrioltrinitrate (BTTN), Nitratoethyl nitramine        (NENA)    -   plasticizers such as dioctyladipate (DOA), isodecyl perlargonate        (IDP) bis(2-ethylhexyl) sebacate, dioctyl maleate (DOM), dioctyl        phthalate (DOP), polyisobutylene, plasticizing oil)    -   oxidizers such as Ammonium Nitrate (AN), hydroxylammonium        Nitrate (HAN), Ammonium dinitramide (AND), Potassium Nitrate,        Barium Nitrate, Sodium Nitrate, Ammonium Perchlorate, Potassium        Perchlorate, Sodium Perchlorate, Lead Nitrate, Anhydrous        Hydrazine, Hydrazinium Nitrate, Nitro-methane, Nitro-ethane,        Nitro-propane)    -   sensitizers such as Diethylamine, Triethylamine, Ethanolamine,        Ethylendiamine, Morpholine, Nitromethane)    -   reactive metal powders such as Aluminum, Magnesium, Boron,        Titanium, Zirconium    -   hydrocarbon fuels such as diesel, kerosene, gasoline, fuel-oil,        motor-oil    -   energetic binders such as polyglycidyl-nitrate (PGN),        polyglycidyl-azide (GAP), polynitratomethyl methyloxetane        (NMMO), poly(3,3 bis(azidomethyl)oxetane (BAMO),        poly(nitramino-methyl-methyl-oxetane (NAMMO),        1,3,3-trinitroazetidine (TNAZ)    -   binders such as Polybutadiene prepolymers, polypropylene glycol        (PPG), polyethylene glycol (PEG), polyesters, polyacrylates,        polymethacrylates, ethylenevynil acetate    -   other materials such as micro particles of resins, Polymeric        foam, Polyurethane rubber, Stearic Acid, Carbon Powder, Silica,        and    -   tagging agents, such as 2,3-dimethyl-2,3-dinitrobutane (DMDNB,        DMNB)

FIG. 14 is a graphical representation of a simple fracture model. Asimple bi-wing fracture plane (340) (only one wing shown) extends into areservoir formation (314). A wellbore (360) (cased or uncased) isrepresentative of the wellbore through which the fracturing fluid (F) isintroduced into the zone, i.e. the “treatment well.” The fracturingprocess results in formation of fractures which are initially propagatedalong planes, the orientation of which are dictated by the in situstress profile of the formation (314). Typically, the planes radiatefrom the wellbore (360). Proppant particles (344) are pumped into thefractures along with the fracturing fluid. After pumping of the fluid(F) ceases, the fracture closes or seals to an effective fracture (350),indicated graphically in cross-sections (352). A typical fracture has amuch greater length (355) than width (353) and can vary in height (354).These dimensions may become critical parameters for selecting size andamounts of proppant, particles and fluid injected into the formation,design of a fracturing plan, etc.

FIG. 15 is a graphical representation of propped fracture model havingproppant particles (344), preferably injected by pumping fracturingfluid (f) into the formation, along with treated, reactive proppantparticles (370). As used herein, “injection” and related terms are usedto include injection, pumping in fluids, and other methods ofintroducing fluids, slurries, gels, and solid-bearing fluids into a zoneof a formation using methods known in the art. The term is usedgenerically and includes introduction of such fluids, etc., into thezone of the formation from a downhole tool positioned adjacent the zone.The non-reactive, untreated proppant particles (344) can be any type ofproppant particle known, or which may become known, in the art and willnot be discussed in detail herein.

FIG. 16 shows an exemplary treated proppant particle (370), having acoating (346) over a proppant particle (348), and exemplary reactiveparticles (362). The proppant particle (348) can be any proppantparticle known in the art which is compatible with the coating andreactions described herein. For example, the proppant particle can be ofvarious shape, geometry, and size, have various structural features, bemade of various materials, have various properties, etc., to provide thedesired propping function of the proppant. Proppant is known in the artby practitioners of ordinary skill and will not be discussed in detailherein. The proppant particle (348) to which the coating is applied canbe identical to the un-treated proppant particles (344) used in theprocess. Delivery, mixing, and types of fracturing fluid are well knownin the art and will not be discussed in detail herein. The proppantparticles (344) and (370) can be delivered to the formation by any knownor discovered means. In a preferred embodiment, the treated anduntreated proppant are of similar size. The particles in the figures arenot to scale for simplicity and purposes of discussion. In oneembodiment, the proppant particles (348) to be treated are smaller thanthe untreated particles (344) such that, after coating, the treated anduntreated proppant is approximately the same size.

An exemplary coating (346) can be rigid or flexible, can fully orpartially cover the proppant particle (348), can be fully or partiallydepleted upon reaction with reactive particles (362), and can be used inconjunction with the various protective or delay coatings and layersdiscussed elsewhere herein. In the preferred embodiment, no protectiveor decay layer is necessary, as the coating provides sufficient physicalstability to reach the fractures intact.

The coating is designed to react with reactive particles (362),producing micro-seismic events. The reactive particles (362) arepreferably smaller than the un-treated proppant particles (344) andtreated proppant particles (370). The reactive particles (362) are shownas solid or semi-solid masses in the figures, however, it is to beunderstood that this is merely a representation and is not limiting asto the form, substance, properties, materials, or state of matter of thereactive particles. For example, the reactive particles (362) can besolids suspended in fracturing fluid, gel, etc., dissolved chemicalcompounds in the fracturing fluid, placed in treatment fluids ahead ofor behind the primary treatment.

Generally, the coating of the treated proppant chemically reacts withreactive particles (362). The coating (346) of the treated proppant canbe said to carry a “payload” of energetic material and is selected toreact with a corresponding “payload” of energetic material in one ormore reactive particles. Contact of corresponding energetic materialscause an interaction producing a micro-seismic event, such as adetonation, explosion, implosion, exothermic reaction, violent chemicalreaction, etc. The concept of “payload” is familiar to those of skill inthe art and can be used to determine the number, weight, volume, orother measure of coating, treated proppant, untreated proppant, andreactive particles to be injected into the formation, and the relativeratios thereof. The reactive particles are preferably much smaller thanthe proppant and coated proppant to enhance their ability to disperseand move freely in the spaces between the proppant particles.

The coating can be applied to the proppant particle by any knownmethods, including micro-encapsulation, pan coating, air-suspensioncoating, centrifugal extrusion, vibration nozzle, spray-drying,ionotropic gelation, coacervation, interfacial polycondensation,interfacial cross-linking, in situ polymerization, water beds, etc.

The treated and untreated proppant particles (344) and (370) can bemixed at the surface, during insertion into the wellbore, at a downholelocation within the wellbore, or in the formation. Where the reactiveparticles and treated proppant is mixed or otherwise combined at thesurface or during injection, it is expected that reactions may welloccur prior to injection into the formation fractures. In such a case,the reactions are designed to produce micro-seismic events at such asmall scale that no damage is done to the well, wellbore, tools.Similarly, the reactions must be controlled to protect personnel. Wherethe treated proppant (370) includes additional layers, coatings,materials, etc., to delay any reaction, there may still be somereactions which occur prior to injection into the formation. In suchinstances, the reactions are designed to be of such small magnitude asto not cause harm. Alternately, these issues can be mitigated or avoidedby introducing the reactive particles to the wellbore or formationgenerally after injection of the proppant particles.

In a preferred embodiment, the coating (346) can be designed to “crack,”thereby exposing the coating to potential reaction, under the increasedpressure on the particles caused when the fractures “relax” or closeupon cessation of pumping of fracturing fluids, or when the fracturinggel, slurry, etc., liquefies or disperses. In another embodiment, themicro-seismic events can occur upon precipitation of reactive particlesfrom the fracturing fluid.

In other embodiments, catalysts and/or inhibitors can be used inconjunction with the reactive particles to control timing of thereactions. Such catalysts and inhibitors can be present in thefracturing fluid, later-added, or injected prior to injection of thereactive particles. Such catalysts and inhibitors could be the productof a secondary chemical reaction that occurs within the fracturingfluid. The reactions of the coating of the treated proppant and thereactive particles is similar to that described elsewhere in thisspecification and will not be repeated here.

For the embodiments and methods described wherein a reactive coating ofa treated proppant particle interacts to create a micro-seismic eventwith one or more reactive particles, the materials listed in thefollowing Groups, alone or in combination, in single or multiple layers,in combination with binding or other materials, in various phases,mixtures, suspensions, etc. can be used, or are expected to operate, asreactive coating materials and/or reactive particle materials:

-   -   high-order explosives such as Pentaerythritoltetranitrate        (PETN), Hexamethylenetetraminemononitrate,        Cyclotrimethylenetrinitramine (RDX),        Cyclotetramethylenetrinitramine (HMX),        Hexanitrohexaazaisowurtzitane (HNIW), Hexanitrosilbene (HNS),        Picrylamino-3,5-dinitropyridine (PYX), Diazodinitrophenol        (DDNP), Lead Azide, Silver Azide, Hydrazine Azide,        Trinitrotoluoene (TNT), Polyazapolycyclic caged Polynitramines        (CL-20), 2,4,6-Trinitrophenylmethylnitramine (Tetryl)    -   energetic plasticizers such as Nitroglycerine (NG),        Ethyleneglycoldinitrate (EGDN), Acetone Peroxide, bis(2,2        di-nitropropyl) acetal/formal (BDNPA/BDNPF), Triethylene        glycol-dinitrate (TEGDN), Diethylene glycol-dinitrate (DEGDN),        Trimethylolethane Trinitrate (TMETN),        1,2,4-Butanetrioltrinitrate (BTTN), Nitratoethyl nitramine        (NENA)    -   plasticizers such as dioctyladipate (DOA), isodecyl perlargonate        (IDP) bis(2-ethylhexyl) sebacate, dioctyl maleate (DOM), dioctyl        phthalate (DOP), polyisobutylene, plasticizing oil)    -   oxidizers such as Ammonium Nitrate (AN), hydroxylammonium        Nitrate (HAN), Ammonium dinitramide (AND), Potassium Nitrate,        Barium Nitrate, Sodium Nitrate, Ammonium Perchlorate, Potassium        Perchlorate, Sodium Perchlorate, Lead Nitrate, Anhydrous        Hydrazine, Hydrazinium Nitrate, Nitro-methane, Nitro-ethane,        Nitro-propane)    -   sensitizers such as Diethylamine, Triethylamine, Ethanolamine,        Ethylendiamine, Morpholine, Nitromethane)    -   reactive metal powders such as Aluminum, Magnesium, Boron,        Titanium, Zirconium    -   hydrocarbon fuels such as diesel, kerosene, gasoline, fuel-oil,        motor-oil    -   energetic binders such as polyglycidyl-nitrate (PGN),        polyglycidyl-azide (GAP), polynitratomethyl methyloxetane        (NMMO), poly(3,3 bis(azidomethyl)oxetane (BAMO),        poly(nitramino-methyl-methyl-oxetane (NAMMO),        1,3,3-trinitroazetidine (TNAZ)    -   binders such as Polybutadiene prepolymers, polypropylene glycol        (PPG), polyethylene glycol (PEG), polyesters, polyacrylates,        polymethacrylates, ethylenevynil acetate    -   other materials such as micro particles of resins, Polymeric        foam, Polyurethane rubber, Stearic Acid, Carbon Powder, Silica,        and    -   tagging agents, such as, 2,3-dimethyl-2,3-dinitrobutane (DMDNB,        DMNB)

Another embodiment and method are presented with respect to FIGS. 17-18.FIG. 17 is a graphical representation of a simple fracture model (441).A simple bi-wing fracture plane (440) (only one wing shown) extends intoa reservoir formation. A wellbore (460) (cased or uncased) isrepresentative of the wellbore through which the fracturing fluid (F) isintroduced into the zone, i.e. the “treatment well.” The fracturingprocess results in formation of fractures which are initially propagatedalong planes, the orientation of which are dictated by the in situstress profile of the formation. Typically, the planes radiate from thewellbore (460).

Proppant particles (444) are pumped into the fractures along with thefracturing fluid. The non-reactive proppant particles (444) can be anytype of proppant particle known, or which may become known, in the artand will not be discussed in detail herein. After pumping of the fluid(F) ceases, the fracture closes or seals to an effective fracture (450),indicated graphically in cross-sections (452). A typical fracture has amuch greater length (455) than width (453) and can vary in height (454).These dimensions may become critical parameters for selecting size andamounts of proppant, particles and fluid injected into the formation,design of a fracturing plan, etc.

Also seen in FIG. 17, positioned in the propped fractures, is aplurality of coated reactive particles (445). The coated reactiveparticles are preferably injected by pumping of fracturing fluid intothe formation concurrently with the injection of the proppant. However,although not anticipated as a common embodiment, coated reactiveparticles (445) can be injected after the proppant. Methods of injectionare described elsewhere herein.

FIG. 18 shows an exemplary coated reactive particle (445), having acoating (446) over a reactive core (448). The coated reactive particles(445) consist of a core section (448) of reactive materials used tocreate a micro-seismic event. The “payload” of the core section (448) ofthe coated reactive particles interacts with one or more catalystparticles (462) to produce a micro-seismic event such as a detonation,explosion, implosion, chemical reaction, etc.

The coated reactive particles (445) have one or more coatings (446). Thecoatings encapsulate, preferably completely, the core section andprevent premature reaction. The coating is selected to delay or controltiming of the interaction between the core reactive material and thecatalyst particles. The coating is removable, such as by dissolution,reaction, decomposition, dissipation, melting, chemical stimulusincluding pH and salinity, etc., in response to the effect of one ormore catalyst particles.

FIG. 18 also shows, in representative form, an exemplary removalparticle (480) selected to remove the coating from the coated, reactiveparticles (445). The removal particle or component is shown as solid fordiscussion purposes, but can be any phase, dissolved or suspended in afluid, etc. The removal particles are selected to remove the coating(446) from the coated reactive particles (445), and can be, for example,a selected fluid (in situ or introduced), such as a solvent, acid,brine, water, diesel, etc. The removal particles can be chemicalcompounds, a chemical wash, brine, etc., naturally occurring in theformation or introduced. Preferably, the removal particles or componentsare in situ and do not require further activity by the user, however,the removal particles can be added by the user and injected into thewell, either before, during, or after injection of the coated reactiveparticles (445). A coating can be rigid or flexible, fully or partiallycover the reactive particle, fully or partially removed upon removal,and used in conjunction with additional coatings as discussed elsewhereherein.

The removal particles (480) can be injected in a carrier fluid, such aswater, brine, diesel, or fracturing fluid, and can act to remove thecoating only in the presence of a catalyst, if desired. The carrierfluid can also be used to inject catalyst particles (462) into theformation. The carrier fluid can transport one or both of the removaland catalyst particles.

FIG. 18 also shows, in representative form, an exemplary catalystparticle (462) or component. The catalyst particles initiate themicro-seismic events by reaction with the reactive core (448) of thecoated reactive particles (445). In a preferred embodiment, afterremoval of sufficient coating (446) by removal particles (480), thereactive cores (448) of the dispersed coated particles (445), arecatalyzed by one or more catalyst particles (462) to initiatemicro-seismic events at each location. As with the removal particles,the catalyst particles are shown as solid in the Figures for discussionpurposes, but may be of any phase, dissolved, suspended, or otherwisecarried in a fluid, present naturally in the formation or introduced bythe user, etc. Further, the catalyst particles can be introduced to thefractures before, during or after introduction of the coated reactiveparticles (445) and before, concurrently with, or after introduction ofthe removal particles (480). The catalyst particles can cause themicro-seismic event as a participant in a chemical reaction, a catalystto a reaction, etc.

In a preferred embodiment, a single type of selected particle canperform both the functions of removal of the coating on the reactiveparticle and triggering of the reactive particle. That is, a singlefluid or material both removes the coating and reacts with the reactivematerial of the reactive particle. In another embodiment, a carrierfluid, such as brine, removes the coating while a dissolved or suspendedmaterial in the brine triggers the reaction. The reaction of reactiveparticles and catalyst particles is similar to that described elsewherein this specification. Further, the use of catalysts, inhibitors, etc.,is discussed elsewhere herein and not repeated here.

Delivery, mixing, and types of fracturing, treatment, and well fluidsare well known in the art and will not be discussed in detail herein.The proppant (444), coated reactive particles (445), removal particles(480), and catalyst particles (462) can be delivered to the formation byknown means.

The materials available for use as removable (non-reactive) coatings,removal particles, reactive materials, triggering materials, etc., arediscussed and listed elsewhere herein and will not be repeated here inthe interest of brevity. Those of skill in the art will recognize thosematerials which are appropriate for use in the various embodimentsdescribed immediately above. The reactive materials listed above can beused in or to create the reactive core and/or reactive particles.Potential removable coating materials, and removal particles and methodsare discussed above herein.

A further embodiment and method are presented with respect to FIGS.19-21. FIG. 19 is a graphical representation of a simple fracture model.A simple bi-wing fracture plane (482) (only one wing shown) extends intoa reservoir formation (481). A wellbore (483) (cased or uncased) isrepresentative of the wellbore through which the fracturing fluid (F) isintroduced into the zone, i.e. the “treatment well.” The fracturingprocess results in formation of fractures which are initially propagatedalong planes, the orientation of which are dictated by the in situstress profile of the formation. Typically, the planes radiate from thewellbore (483).

Proppant particles (484) are pumped into the fractures along with thefracturing fluid. The proppant particles (484) can be any type ofproppant particle known, or which may become known, in the art and willnot be discussed in detail herein. After pumping of the fluid (F) ceasesor is reduced, the fracture closes or seals to an effective fracture(485), indicated graphically in cross-sections (486). A typical fracturehas a much greater length (488) than width (489) and can vary in height(487). These dimensions may become critical parameters for selectingsize and amounts of proppant, particles and fluid injected into theformation, design of a fracturing plan, etc.

As further shown in FIG. 19, positioned in the propped fractures, is aplurality of acoustic particles (490). The acoustic particles arepreferably injected by pumping of fracturing fluid into the formationconcurrently with the injection of the proppant. However, although notanticipated as a common embodiment, acoustic particles (490) can beinjected after the proppant. Methods of injection are describedelsewhere herein.

FIG. 20 shows an exemplary acoustic particle (490), having an optionalcoating (491) over a core (492). The acoustic particle (490) consists ofa core section (492) that generates a detectable acoustic signal.Acoustic particle (490) emits a detectable acoustic emission uponexertion of preselected compressive force by the closing of the fractureafter injection of fracturing fluid (F). As used herein with respect tothis embodiment, “compressive force” encompasses forces that act uponacoustic particles (490) resulting in generation of a detectableacoustic signal. The compressive force can be compression, shear orboth. The application of the compressive force preferably reduces thesize of the acoustic particle in at least one direction. Alternatively,however, the compressive force can cause an acoustic signal without suchreduction, as for example in twinning. It is understood that acousticparticles (490) may be used separately or in combination with the AS,T1, T2 and/or T3 particles and methods previously described herein. Manymaterials capable of generating a detectable signal may be used inaccordance with the practice of the invention. One class of particularlydesirable materials are those that emit acoustic signals such asproduced when subjected to a compressive force. Desirable materialsinclude metals, and in particular, those having a crystallinemicrostructure. Tin, zinc, gallium, niobium, indium, and alloys of suchmetals that generate detectable acoustic signals in subterraneanenvironments are desirable. It is noted that metals (e.g., gallium) thathave melting points below temperatures expected during the frackingprocess may be less desirable, depending upon the circumstances andconditions, and therefore alloys of such metals or combinations thereofthat have a higher melting point(s) may be preferred.

There is no limitation on the size or dimensions of the acousticparticles (490) relative to proppant (484). It is preferable thatacoustic particles have an average diameter than is similar to theaverage diameter of proppant. In another aspect, such as shown in FIG.19, the average diameter of the acoustic particles (490) is larger thanproppant (484).

It is expected that the acoustic particle generates an acoustic signalor vibration approximately in the range of about 20 Hz to about 200 kHz,more preferably about 500 Hz to about 5 kHz, and even more preferablyabout 750 Hz to about 1,500 Hz.

For protecting the properties of acoustic particles during injection, anoptional protective coating (491) may be added. The coating is selectedto protect the acoustic particle during transport, injection, etc. Thecoating (491) encapsulates the particle, preferably completely, althoughpartial encapsulation may be appropriate in certain applications. Thiscoating may be designed to decompose, dissolve, decay or otherwisedissipate over time, upon contact with a selected fluid (in situ orintroduced), such as a solvent, acid, brine, water, etc., or uponexposure to other environmental parameters, such as temperature,pressure, salinity, pH, etc. Alternatively, the coating is selected todeform sufficiently to allow transfer of compressive forces to the core.

Where a coating (491) is desired which dissipates, it is preferably madeof one or more of the exemplary shell, capsule or coating materialsdescribed previously hereinabove.

FIG. 21 shows, in representative form, an optional reactive layer (493),which interacts with one or more catalyst particles (494) to produce amicro-seismic event such as a detonation, explosion, implosion, chemicalreaction, etc., that may be used in combination with the acousticparticles (490) to form an additive or synergistic reaction for thegeneration of a detectable signal. Reactive materials include thoseprovided above.

Where a reactive layer (493) is included, coating (491) also serves toprevent interaction between reactive materials in the reactive layer andcatalyst particles, such as those described previously.

In a further aspect, FIG. 21 shows an exemplary removal particle (495)selected to remove the coating from acoustic particles (490). Theremoval particle or component is shown as solid for discussion purposes,but can be any phase, dissolved or suspended in a fluid, etc. Theremoval particles are selected to remove the coating (491) from acousticparticles (490), and can be, for example, a selected fluid (in situ orintroduced), such as a solvent, acid, brine, water, diesel, etc. Theremoval particles can be chemical compounds, a chemical wash, brine,etc., naturally occurring in the formation or introduced. Preferably,the removal particles or components are in situ and do not requirefurther activity by the user, however, the removal particles can beadded by the user and injected into the well, either before, during, orafter injection of the coated acoustic particles (490). A coating can berigid or flexible, fully or partially cover the reactive particle, fullyor partially removed upon removal, and used in conjunction withadditional coatings as discussed elsewhere herein.

The removal particles (495) can be injected in a carrier fluid, such aswater, brine, diesel, or fracturing fluid, and can act to remove thecoating only in the presence of a catalyst, if desired. The carrierfluid can also be used to inject catalyst particles (494) into theformation. The carrier fluid can transport one or both of the removaland catalyst particles.

FIG. 21 also shows, in representative form, an exemplary catalystparticle (494) or component. The catalyst particles initiate themicro-seismic events by reaction with the reactive layer (493) of theacoustic particles (490). In a preferred embodiment, after removal ofsufficient coating (491) by removal particles (495), the reactive layer(493) is triggered by one or more catalyst particles (494) to initiatemicro-seismic events at each location. As with the removal particles,the catalyst particles are shown as solid in the Figures for discussionpurposes, but may be of any phase, dissolved, suspended, or otherwisecarried in a fluid, present naturally in the formation or introduced bythe user, etc. Further, the catalyst particles can be introduced to thefractures before, during or after introduction of acoustic particleshaving a reactive layer and before, concurrently with, or afterintroduction of the removal particles (495). The catalyst particles cancause the micro-seismic event as a participant in a chemical reaction, acatalyst to a reaction, etc.

In a preferred embodiment, a single type of selected particle canperform both the functions of removal of the coating on the reactiveparticle and triggering of the reactive particle. That is, a singlefluid or material both removes the coating and reacts with the reactivematerial of the reactive particle. In another embodiment, a carrierfluid, such as brine, removes the coating while a dissolved or suspendedmaterial in the brine triggers the reaction. The reaction of reactiveparticles and catalyst particles is similar to that described elsewherein this specification. Further, the use of catalysts, inhibitors, etc.,is discussed elsewhere herein and not repeated here.

Delivery, mixing, and types of fracturing, treatment, and well fluidsare well known in the art and will not be discussed in detail herein.The proppant (484), acoustic particles (490) optionally having coating(491) and optional reactive layer (493), removal particles (494), andcatalyst particles (495) can be delivered to the formation by knownmeans.

The materials available for use as removable (non-reactive) coatings,removal particles, reactive materials, triggering materials, etc., arediscussed and listed elsewhere herein and will not be repeated here inthe interest of brevity. Those of skill in the art will recognize thosematerials which are appropriate for use in the various embodimentsdescribed immediately above. The reactive materials listed above can beused in or to create the reactive layer. Potential removable coatingmaterials, and removal particles and methods are discussed above herein.

While this invention has been described with reference to illustrativeembodiments, this description is not intended to be construed in alimiting sense. Various modifications and combinations of theillustrative embodiments as well as other embodiments of the inventionwill be apparent to persons skilled in the art upon reference to thedescription. It is, therefore, intended that the appended claimsencompass any such modifications or embodiments.

It is claimed:
 1. A method for mapping of fractures within a hydrocarbonbearing zone of a subterranean formation, the zone having a wellboreextending therethrough, the method comprising the steps of: injecting atleast one acoustic particle into at least one fracture in the zone ofthe formation, wherein the at least one acoustic particle comprises ametal selected from the group consisting of tin, zinc, gallium, niobium,indium, any alloy of any of the foregoing metals, and any mixturethereof, and wherein the metal emits a detectable acoustic signal withinthe fracture upon application of a compressive force; and detecting saidacoustic signal.
 2. The method of claim 1, further comprising the stepof injecting proppant particles into the fracture.
 3. The method ofclaim 2, wherein the step of injecting at least one acoustic particle isperformed concurrently with the step of injecting proppant particles. 4.The method of claim 1, wherein the at least one acoustic particlefurther comprises a protective layer.
 5. The method of claim 4, whereinthe at least one acoustic particle further comprises a reactive layer.6. The method of claim 5, further comprising the step of injecting atleast one reactive particle into the at least one fracture.
 7. Themethod of claim 5, wherein the at least one reactive particle reactswith the reactive layer of the acoustic particle.
 8. The method of claim1, wherein the compressive force is applied by closure of the fracture.9. The method of claim 8, wherein the compressive force cause reductionof the acoustic particle size in at least one direction.
 10. The methodof claim 1, further comprising the step of ceasing pumping of fracturingfluid.
 11. A method for mapping of fractures within a hydrocarbonbearing zone of a subterranean formation, the zone having a wellboreextending therethrough, the method comprising the steps of: injecting atleast one acoustic particle having a protective layer into at least onefracture in the zone of the formation, wherein the at least one acousticparticle comprises a metal selected from the group consisting of tin,zinc, gallium, niobium, indium, any alloy of any of the foregoingmetals, and any mixture thereof, and wherein the metal emits adetectable acoustic signal within the fracture upon application of acompressive force; removing at least a portion of the protective layerof the at least one acoustic particle; and detecting said acousticsignal.
 12. The method of claim 11, wherein the step of removing atleast a portion of the protective layer utilizes in situ materials,chemicals, fluid, or compounds found in the formation.
 13. The method ofclaim 11, wherein the step of removing further includes allowingcracking the protective layer with increased pressure.
 14. The method ofclaim 13, wherein the step of cracking the protective layer withincreased pressure further comprises increasing pressure by cessation offracturing activities.